CN114981602A

CN114981602A - Method for improved cold box operation of partially condensed carbon monoxide

Info

Publication number: CN114981602A
Application number: CN202080093052.1A
Authority: CN
Inventors: J·M·施瓦茨; B·S·卡尔普; A·M·瓦尔塔; M·M·沙
Original assignee: Praxair Technology Inc
Current assignee: Praxair Technology Inc
Priority date: 2020-02-14
Filing date: 2020-10-30
Publication date: 2022-08-30
Also published as: WO2021162759A1; CA3165671A1; EP4103900A1; US20210254891A1

Abstract

The present invention relates to a method and system for separating carbon monoxide from a syngas mixture with a high methane content by a cryogenic plant in which a partial condensation cycle is typically employed, and more particularly, to mixing a methane-rich liquid exiting a distillation column with a lower boiling mixture such that the boiling point of the mixed stream is lower than the boiling point of the methane-rich liquid.

Description

Method for improved cold box operation of partially condensed carbon monoxide

Background

Technical Field

The present invention relates to a process for separating carbon monoxide from a synthesis gas containing hydrogen, carbon monoxide, methane, water and carbon dioxide. More particularly, the invention relates to a process for separating carbon monoxide from a synthesis gas mixture having a high methane content by a cryogenic plant in which a partial condensation cycle is not typically employed, and more particularly, to mixing a methane-rich stream exiting the bottom of a distillation column separating carbon monoxide and methane with a stream having a lower boiling point, which mixed stream then enters a heat exchanger such that the boiling point of the mixed stream is lower than the boiling point of the initial methane-rich stream. This change enables the use of a simpler, cheaper partial condensation process instead of a methane scrubbing process for the same syngas feed.

Prior Art

Hydrocarbons, such as natural gas, naphtha and Liquefied Petroleum Gas (LPG), can be catalytically converted using steam or oxygen to obtain synthesis gas (i.e., hydrogen (H)) ₂ ) Carbon monoxide (CO), methane (CH) ₄ ) Water (H) ₂ O) and carbon dioxide (CO) ₂ ) Is commonly referred to as "syngas"). Reformer processes, including reforming in a partial oxidation reformer or a steam methane reformer, are well known and are commonly used to obtain synthesis gas that is ultimately used to produce hydrogen or chemicals such as methanol and ammonia. Conventional techniques for separating CO from the remaining syngas components are known. For example, cryogenic purification methods such as partial condensation or scrubbing with liquid methane (known as the methane scrubbing process) are well known techniques.

Syngas typically contains significant amounts of CO that must be removed ₂ And H ₂ O, which is generally carried out by the following method: water is condensed and the liquid removed, most of the carbon dioxide is removed by amine absorption, and the remaining CO is removed in a Temperature Swing Adsorption (TSA) unit commonly referred to as a dryer ₂ And water. Carbon dioxide and water must be removed to very low levels, typically less than 50ppb, to prevent their freezing in downstream process heat exchangers. The syngas may then be sent to a cryogenic separation unit, known as a cold box, for CO purification.

There are two common types of CO cold boxes, partial condensation and methane scrubbing. The present invention relates to a partially condensed cold box in which a syngas feed is partially condensed in a heat exchanger and separated using a phase separator to separate most of the hydrogen in the feed from the condensed components. If the cold box feed contains too much methane, the process suffers from the limitation that it does not function properly. When the methane content is high, typically above about 2.5%, the load on the recycle compressor increases and the once-through CO recovery decreases to the point where the more expensive methane wash cold box is typically used.

U.S. Pat. No. 4,805,414 to Fisher discloses a partial condensation process for CO purification in which the CO/CH is separated ₄ The methane at the bottom of the separation column is mixed with the entire flash gas stream before it enters the heat exchanger. The process includes mixing a portion of the crude hydrogen vapor stream exiting the high pressure separator with a methane stream.

U.S. Pat. No. 5,609,040 to Billy et al depicts a partial condensation process for CO purification in which the CO/CH will leave ₄ The methane at the bottom of the separation column is mixed with nitrogen from the distillation column that removes the nitrogen from the CO product and the crude hydrogen that exits from the first separator as a vapor. The process requires a denitrogenation column and does not recover hydrogen by-product.

U.S. Pat. No. 5,832,747 to Bassett et al shows a partial condensation process for CO purification and syngas production with exit of CO/CH ₄ The methane at the bottom of the separation column is mixed with the expanded vapor stream exiting the phase separator before it enters the heat exchanger. This flow is the result of the third separator being connected in series after the second high pressure separator, which is connected in series after the first high pressure separator. The process described in us patent 5,832,747 requires multiple separators since a 1:1 syngas is also produced.

U.S. Pat. Nos. 6,062,042 to McNeil et al and 6,070,430 to McNeil et al show a partial condensation process for CO purification in which the CO/CH will exit ₄ The methane at the bottom of the separation column is mixed with nitrogen from a distillation column that separates the CO product from the nitrogen impurities.

Granted Gallarda et alHuman us patent 6,098,424 describes a partial condensation process for CO purification and syngas production, where CO/CH will leave ₄ The methane at the bottom of the separation column mixes with the entire flash gas stream from the top of the stripper column. No process for mixing only a portion of the flash gas stream is contemplated.

U.S. Pat. No. 6,161,397 to McNeil et al shows a partial condensation process for CO purification and syngas production where the CO/CH will exit ₄ The methane at the bottom of the separation column is mixed with the crude carbon monoxide stream which is heated prior to mixing.

U.S. patent 6,467,306 to McNeil is similar to U.S. patent 5,832,747. Both show a partial condensation process for CO purification, where the CO/CH will leave ₄ The methane at the bottom of the separation column is mixed with the heated vapor stream from the separator before it enters the heat exchanger. However, the vapor stream in this process is the result of the vapor portion of the second separator feed in series. The process described in us patent 6,467,306 uses multiple separators which increases the capital cost of the process.

U.S. Pat. No. 6,568,206 to Scharpf shows a partial condensation process for CO purification, in which the CO/CH is separated ₄ The methane stream at the bottom of the separation column is mixed with the hydrogen stream across the membrane and then cooled and expanded to provide additional refrigeration in the cold box. The process of the present invention does not involve a membrane and does not have a flow equivalent to an expanded membrane permeate mixed with methane.

In the related art for CO production, there is a stream with a lower boiling point with the CO/CH from ₄ Several examples of mixing of methane streams at the bottom of the separation column, but none of these examples use only a portion of the lower boiling stream to control the boiling point of the mixture and thus the location where the stream boils in the heat exchanger. Furthermore, as shown in the comparative examples, using only a portion of the lower boiling stream provides advantages over the prior art processes as described herein.

To overcome the disadvantages of the related art, it is an object of the present invention to provide an improved process and apparatus to overcome the operational limitations caused by high methane in the partially condensed cold box feed while still maintaining high CO recovery.

The object of the invention is to reduce the compression power, in particular for the stream recirculated to the cold box.

It is another object of the present invention to increase the operating range of a partially condensing cold box to allow for an increase in methane in the feed due to upscaling in upstream processes while maintaining high CO recovery and flux.

It is another object of the present invention to achieve high recovery of hydrogen product. Hydrogen is a valuable by-product of the process disclosed in the present invention and the inability to recover it represents a significant economic disadvantage.

It is another object of the present invention to minimize the amount of CO in the gas phase of the partially condensed syngas feed to reduce the recycle compression power. This is accomplished by minimizing its temperature exiting the heat exchanger, and by providing the coldest stream possible to the heat exchanger to cool the syngas feed.

It is another object of the present invention to minimize the number of separators and the capital costs associated with them.

It is another object of the present invention to provide a process that does not require a denitrification column and the capital costs associated with such a column.

It is another object of the present invention to avoid the use of membranes and the capital costs associated therewith.

Other objects and aspects of the present invention will become apparent to those of ordinary skill in the art upon review of the specification, drawings and appended claims.

Disclosure of Invention

The invention is applicable to the separation of carbon monoxide from synthesis gas using a low temperature partial condensation process. In particular, the partial condensation processes of the prior art suffer from low carbon monoxide recovery or high power consumption at syngas methane contents above about 2.5%. The present invention provides a process in which the boiling point of the methane-rich liquid byproduct stream leaving the distillation column entering the cold end of the process heat exchanger is reduced, allowing heat to be removed from the feed stream at lower temperatures, producing a partially condensed syngas with lower temperatures, increasing overall and once-through CO recovery, while reducing recycle compression power.

The boiling point of the methane stream can be reduced by mixing it with a portion of the hydrogen rich vapor stream exiting the high pressure separator or a portion of the hydrogen rich vapor stream exiting the low pressure separation unit. This can significantly improve the performance and efficiency of the process heat exchanger.

Drawings

The objects and advantages of the present invention will be better understood from the following detailed description of the preferred embodiments of the invention taken in conjunction with the accompanying drawings, in which like numerals refer to like features throughout, and in which:

FIG. 1 is a process flow diagram illustrating an embodiment of the invention in which a portion of the vapor stream produced by the low pressure separation unit is mixed with a methane-rich liquid exiting a distillation column to produce a mixed stream that boils at a lower temperature than the methane-rich liquid in the process heat exchanger; and is

Fig. 2 is a process flow diagram illustrating an embodiment of the invention in which a portion of the vapor stream produced by the high pressure separator is mixed with the methane-rich liquid exiting the distillation column to produce a mixed stream that boils at a lower temperature than the methane-rich liquid in the process heat exchanger.

Detailed Description

According to one aspect of the invention as shown in fig. 1, a method for separating carbon monoxide from a syngas feedstock in a partially condensed carbon monoxide cold box is provided. The method comprises the following steps:

at near ambient temperature and high pressure, typically between 250psig and 500psig, the syngas feed (1) is mixed with a high pressure recycle (34) and fed to a dryer (110) that removes impurities, including remaining water and carbon dioxide, to produce a cold box feed (2). The cold box feed (2) enters the process heat exchanger (101) located inside the cold box (100) and leaves the process heat exchanger (101) as a cooled cold box feed (3), which is typically between 130K and 140K. The cooled cold box feed (3) is split into a partially condensed feed (4) and a reboiler feed (6). The partially condensed feed (4) is further cooled in the process heat exchanger (101) to a temperature typically between 85K and 95K, so that a portion of this stream is condensed and leaves the process heat exchanger as partially condensed feed (5), which is fed to the high pressure separator (102). The reboiler feed (6) provides heat to the reboiler (106) and exits the reboiler as a cooled reboiler feed (7) that is also fed to the high pressure separator (102). The high pressure separator (102) separates the mixture fed thereto to produce a high pressure carbon monoxide rich feed liquid (10) and a crude hydrogen vapor (8) which is warmed in the process heat exchanger (101) to produce warmed crude hydrogen (9) which is then fed to the pressure swing adsorption system (108).

The high pressure carbon monoxide rich feed liquid (10) is expanded through valve (103) to produce a low pressure separation unit feed (11) that is fed to a low pressure separation unit (104) typically operating between 20psig and 80 psig. The low pressure separation unit (104) may be a single stage separator vessel, a dual stage separator, a multi-stage distillation or stripping column, or other device that removes a majority of the hydrogen contained in the low pressure separation unit feed (11). Generally, it is expected that separation units with more stages will produce higher purity CO products with less hydrogen, but will also have higher capital costs. Figure 1 shows a single stage separator. A dual stage separator or multi-stage column may require other streams. The choice of equipment for the low pressure separation unit (104) depends on the hydrogen purity requirements of the CO product. The low pressure separation unit (104) produces a cold hydrogen-rich flash gas (12) and a crude CO liquid (14). A portion of the cold flash gas (12A) is mixed with a methane-rich liquid (20) as described below. This portion of the cold flash gas (12A) is in the range of about 1% to 99% by volume, preferably 5-40% by volume, and most preferably 10-30% by volume. The remainder of the cold flash gas (12) is warmed in the process heat exchanger (101) to produce flash gas (13) which is typically near ambient temperature. The crude CO liquid (14) is split into a direct column feed (15) and a liquid split stream feed (16). The direct column feed (15) is fed directly to the distillation column (105), while the liquid split stream feed (16) is at least partially vaporized in the process heat exchanger (101) to form a vaporized column feed (17) that is fed to the distillation column (105) at a location below the location of the direct column feed (15).

Distillation column (105) typically operates between 5psig and 25psig and separates the streams fed thereto to produce a cold CO product (23), typically between 82K and 90K, and a methane-rich liquid (20), typically between 105K and 110K. A reboiler liquid stream (18) is removed from the distillation column (105) and heated in a reboiler (106) to produce a partially boiled bottoms (19) which is returned to the sump of the distillation column (105). The methane-rich liquid (20) is mixed with a portion (12A) of the cold flash gas to form a mixed stream (20A). The boiling point of the mixed stream (20A) is lower than the boiling point of the methane-rich liquid so that it vaporizes at a lower temperature when heated and vaporized in the process heat exchanger (101) to produce the fuel gas (21).

The amount of the portion of cold flash gas (12A) mixed with the methane-rich liquid (20) is determined by using the minimum value necessary to provide the advantages of the present invention in the process heat exchanger (101). If not enough cold flash gas is mixed with the methane-rich liquid, the heat exchanger will be less efficient and the temperature of the partially condensed feed (5) will be too high, resulting in unnecessary recycle flow and compression power. If too much cold flash gas is mixed with the methane-rich liquid, the CO and hydrogen products will be lost without providing the additional benefits of the process heat exchanger. This is shown in the comparative examples described herein.

The cold CO product (23) is mixed with turbine exhaust (28) to form a mixed cold CO product (24) which is heated in a process heat exchanger (101) to produce a warm CO product (25) which is typically compressed (not shown) and removed at higher pressure in part as a recovered product. The remaining compressed warm CO product is recycled to the cold box as CO recycle (26), which is typically between 100psig and 300 psig. The CO recycle (26) may be at the same pressure as the recovered product or at a different pressure.

The CO recycle (26) is cooled in the process heat exchanger (101) and split into turbine feed (27) and warm CO reflux (29). The turbine feed (27), which is typically at a similar temperature to the cooled cold box feed (3) between 125K and 145K, is expanded in turbine (107) to produce turbine exhaust (28), which is at a lower pressure, typically at or slightly above the distillation column pressure of 5psig to 25psig, and at a lower temperature than the turbine feed (27), typically near its dew point or possibly containing a small amount of liquid. The necessary refrigeration provided by the turbine may be provided in other ways, including liquid nitrogen addition (not shown). The warm CO reflux (29) is further cooled and condensed in a process heat exchanger (101) to produce cold CO reflux liquid (30) which is fed as a refluxed stream to a distillation column (105) to improve the cold CO product (23) purity.

The pressure swing adsorption system (108) produces a high purity hydrogen product (31) and a tail gas (32). The tail gas (32) and the flash gas (13) are mixed to produce a low pressure recycle mixture (33). The low pressure recycle mixture (33) is compressed in a recycle gas compressor (109) to produce a high pressure recycle (34) which is mixed with the syngas feed (1) and fed to the dryer (110).

According to another aspect of the invention as shown in fig. 2, a method for separating carbon monoxide from a syngas feedstock in a partially condensed carbon monoxide cold box is provided. In this case, a portion (8A) of the crude hydrogen vapor (8) is mixed with the methane-rich liquid (20) after being expanded in the crude hydrogen vapor expansion valve (103A) to produce a mixed stream (20A). This expansion reduces the pressure of the portion of crude hydrogen vapor (8A) from about 250-500psig to about 5-25psig and reduces the temperature from about 85-95K to about 75-90K. The portion of crude hydrogen (8A) is in the range of about 0.5% to 99% by volume, preferably 0.5-30% by volume, and most preferably 0.5-10% by volume. The degree of cooling of the mixed stream must be carefully monitored to ensure that the methane in the mixed stream does not freeze. The boiling point of the mixed stream (20A) is lower than the boiling point of the methane-rich liquid so that it vaporizes at a lower temperature when heated and vaporized in the process heat exchanger (101) to produce the fuel gas (21).

An important aspect of the present invention is that it has a higher CO recovery at lower power consumption compared to alternative processes in the related art. This is achieved by mixing the methane-rich liquid (20) with another stream having a lower boiling point, such that the boiling point of the mixed stream is lower than the boiling point of the methane-rich liquid (20). This improves the efficiency of the process heat exchanger (101) and reduces the temperature of the partially condensed feed (5), thereby reducing the amount of crude hydrogen vapor (8) and subsequent recycle compression power.

Another important aspect of the invention is that it enables the operation of the partially condensed CO cold box for feeds with a higher methane content, with a higher recovery and lower power consumption than the processes of the related art, due to typical or unusual conditions. These advantages are shown in the following examples.

Comparative example

The process shown in fig. 1 was modeled with differences in splitting between the cold flash gas (12) and the portion (12A) mixed with the methane-rich liquid (20). Surprisingly, there is an optimal split flow for maximizing the overall recovery of carbon monoxide product.

Table 1 shows the results. In case 1, none of the cold flash gas is mixed with the methane-rich liquid. In

case

2, 20 vol% of the cold flash gas was mixed with the methane-rich liquid. In case 3, all of the cold flash gas is mixed with the methane-rich liquid. Both case 1 and case 3 are provided as comparative results to demonstrate the advantages of the present invention. All cases had a 4802lbmol/hr syngas feed at 100F and 361psig with a composition of 65.83% hydrogen, 22.86% carbon monoxide, 11.10% methane, and 0.21% nitrogen. In all cases at 125psig, a carbon monoxide product of at least 99% purity was produced. In all cases hydrogen product was produced at 320 psig. In all cases a Δ T of at least 1K is maintained in the heat exchanger.

TABLE 1

This stream enters the heat exchanger at 98.8K as 22% vapor.

Comparing case 1 with case 2, the effect of mixing 20 vol% cold flash gas (12) with methane-rich liquid (20) is that the performance of the process heat exchanger (101) is significantly improved, since the boiling point of the mixture is lower than that of the methane-rich liquid. This can be seen by comparing the temperature at which 10% of the stream is vapor. In case 2, the temperature was 104.3 ° K, and in case 1, it was 107.3 ° K. This results in increased heat transfer at lower temperatures inside the process heat exchanger, resulting in lower temperatures (92.27 ° K versus 94.25 ° K) in the high-pressure separator (102). The lower temperature effect in the high pressure separator is that less CO leaves through the top of the separator with the raw hydrogen (8), resulting in less off-gas flow (32) (1134lbmol/hr versus 1249lbmol/hr), and thus less recycle compressor flow and power (2602kW versus 2932 kW).

In case 1, the effect on the heat exchanger extends to the distillation column (105) without the substance mixing with the methane-rich liquid. The temperature differential in the heat exchanger must be maintained by increasing the high pressure separator temperature (as described above) and also by changing the composition of the methane-rich liquid. In case 2, the methane-rich liquid typically used as the fuel stream may contain 92% methane. In case 1, the composition had to be reduced to 89% methane to maintain a Δ T in the heat exchanger, resulting in more carbon monoxide going to the fuel stream, thereby reducing the CO recovery from 94.49% to 93.87% with a total CO product loss of 7 lbmol/hr.

As shown by the comparison results, case 2, where 20 vol% of the cold flash gas was mixed with the methane-rich liquid, had higher CO recovery and reduced compression power when compared to case 1. This provides a significant advantage over case 1. Case 1 does recover more hydrogen, but because the value of hydrogen on a volumetric basis is less than carbon monoxide, the advantages of case 1 are not sufficient to overcome the reduction in CO recovery or the increase in power required.

Comparing case 2 with case 3, the effect of mixing 20 vol% of the cold flash gas with the methane-rich liquid versus mixing all of the cold flash gas is that the CO recovery (94.49% versus 90.13%) and the hydrogen recovery (99.57% versus 98.04%) are significantly higher in case 2. This is because any CO and hydrogen contained in the cold flash gas mixed with the methane-rich liquid is lost to fuel and not recovered as product. Although the compression power for case 3 was lower (3870kW versus 4343kW), the loss of CO (4.6% reduction) and hydrogen (1.6% reduction) products significantly exceeded the power savings because there was less recycle flow. Thus, case 2 also has a significant advantage over case 3.

Mixing crude hydrogen with a methane-rich liquid has a similar effect. If no material is mixed, as described above in case 1, the performance of the heat exchanger suffers, resulting in a higher high pressure separator temperature. This situation also requires the distillation column to be operated with more CO product lost to the methane-rich liquid. If all of the crude hydrogen streams are mixed, the loss of hydrogen product makes it cost prohibitive in any situation where the hydrogen product has any value. Typically, only a small amount of the crude hydrogen stream needs to be mixed with the methane-rich liquid to provide a benefit similar to that seen in case 2 above.

While the invention has been described in detail with reference to specific embodiments thereof, it will be apparent to one skilled in the art that various changes and modifications can be made, and equivalents employed, without departing from the scope of the appended claims.

Claims

1. A method for separating carbon monoxide from a syngas feedstock in a partially condensed carbon monoxide cold box, the method comprising:

cooling and partially condensing said synthesis gas feedstock containing carbon monoxide and hydrogen in a process heat exchanger to produce a cooled and partially condensed synthesis gas feed stream;

separating the cooled and partially condensed syngas feed stream in a high pressure separator into a crude hydrogen vapor stream and a high pressure carbon monoxide-rich liquid feed stream;

feeding the high pressure carbon monoxide-rich liquid feed stream to a low pressure separation unit operating at a pressure lower than the high pressure separator, wherein cold flash gas is separated from the crude CO liquid stream;

separating the crude CO liquid stream in a distillation column to form a purified carbon monoxide vapor stream and a methane-rich liquid byproduct stream containing at least 50% methane;

separating a portion of the cold flash gas having at least 1 vol% and less than 99 vol% and mixing the cold flash gas portion with the methane-rich liquid byproduct stream prior to introducing the mixture into the process heat exchanger.

2. The process of claim 1, wherein 5-40 vol% of the cold flash gas is mixed with the methane-rich liquid prior to introducing the mixture into the process heat exchanger.

3. The process of claim 1, wherein 10-30 vol% of the cold flash gas is mixed with the methane-rich liquid prior to introducing the mixture into the process heat exchanger.

4. The method of claim 1, further comprising: the crude hydrogen stream is warmed in the process heat exchanger and then fed to a pressure swing adsorption unit for further purification, with tail gas recycled to the cold box.

5. The process of claim 1, wherein the portion of the cold flash gas that is not mixed with methane-rich liquid is warmed in the process heat exchanger and recycled to the cold box.

6. A method for separating carbon monoxide from a syngas feedstock in a partially condensed carbon monoxide cold box, the method comprising:

separating the crude CO liquid stream in a distillation column to form a purified carbon monoxide vapor stream and a methane-enriched liquid by-product stream containing at least 50% methane;

wherein at least 0.5% by volume and less than 99% by volume of a portion of the crude hydrogen vapor stream is mixed with the methane-rich liquid prior to introducing the mixture into the process heat exchanger and none of the remaining crude hydrogen is expanded in the turboexpander.

7. The process of claim 6, wherein 0.5-30 vol% of the crude hydrogen vapor is mixed with the methane-rich liquid prior to introducing the mixture into the process heat exchanger.

8. The process of claim 6, wherein 0.5-10 vol% of the crude hydrogen vapor is mixed with the methane-rich liquid prior to introducing the mixture into the process heat exchanger.

9. The method of claim 6, further comprising: the portion of the crude hydrogen stream that is not mixed with the methane-rich liquid is warmed in the process heat exchanger and then fed to a pressure swing adsorption unit for further purification, with the tail gas recycled to the cold box.

10. The process of claim 6 wherein the cold flash gas is warmed in the process heat exchanger and recycled to the cold box.

11. The method of claim 6, wherein the portion of the crude hydrogen vapor mixed with the methane-rich liquid is expanded to reduce its pressure and temperature prior to mixing.

12. An apparatus for separating carbon monoxide from a syngas feedstock in a partially condensed carbon monoxide cold box, the apparatus comprising:

a process heat exchanger;

a high pressure separator;

a low pressure separation unit operating at a lower pressure than the high pressure separator;

a distillation column for separating a crude CO liquid stream to form a purified carbon monoxide vapor stream and a methane-rich liquid byproduct stream containing at least 50% methane;

a turbine for providing refrigeration;

at least two connected lines that mix the methane-rich liquid byproduct stream with a portion of the stream produced in the cold box that has a lower boiling point prior to introducing the mixed stream into the process heat exchanger.

13. The apparatus of claim 12, wherein the mixed stream comprises a portion of the cold flash gas.

14. The apparatus of claim 13, wherein 5-40 vol% of the cold flash gas is mixed with the methane-rich liquid prior to introducing the mixed stream into the process heat exchanger.

15. The apparatus of claim 13, wherein 10-30 vol% of the cold flash gas is mixed with the methane-rich liquid prior to introducing the mixture into the process heat exchanger.

16. The apparatus of claim 12, wherein the mixed stream is a mixture of the methane-rich liquid byproduct and a portion of the crude hydrogen vapor stream.

17. The apparatus of claim 16, wherein 0.5 to 30 vol% of the crude hydrogen vapor stream is mixed with the methane-rich liquid prior to introducing the mixture into the process heat exchanger.

18. The apparatus of claim 16, wherein 0.5-10 vol% of the crude hydrogen vapor stream is mixed with the methane-rich liquid prior to introducing the mixture into the process heat exchanger.